This invention relates to the recovery of oil from subterranean reservoirs and more particularly concerns an improved process for recovering oil from porous reservoirs having heterogeneous permeability, utilizing the injection of fluids and gases.
Significant quantities of crude oil exist in underground formations. These substantial amounts remain even after completion of primary recovery operations. Because of this, techniques have been developed for stimulating production from such reservoirs. Such methods include water flooding, gas flooding and steam injections, but none to date have been very successful. One variation of gas and steam flooding is foam injection. The objective is to improve the sweep efficiency of gas and steam in the reservoir. However, this method has been largely unsuccessful because of an incorrect sequence of fluid injections, improper selection of reservoirs for treatment, and the incorrect timing to initiate foam injection
Generally, water flooding is ineffective for displacing the oil, because of the high oil-water interfacial tension and the rich viscosity of the oil. Steam injection lowers the viscosity of the oil, but requires the availability of inexpensive fuel and a large supply of clean water. A variation on steam injection is known as the huff-and-puff method, which is disclosed by West in U.S. Pat. No. 3,782,470. In huff-and-puff steam injection, the well is used for alternate injection of steam and production of reservoir fluids. In a recent variation of the huff-and-puff method, immediately following the injection phase of steam, which lowers the viscosity of the oil, a noncondensing, nonoxidizing gas is injected at ambient temperature. The gas displaces the low viscosity oil and improves production rates, reduces the amount of steam required, and improves the oil-water ratio of the well. However, where a multi-component gas is employed, such as natural gas, the higher molecular weight hydrocarbons tend to condense as the formation cools following steam injections. The condensed hydrocarbons have high solubility and even miscibility with most crudes. As a result, crude oil may be miscibly displaced from the vicinity of the wellbore, resulting in reduced permeability of oil at the wellbore.
The areal sweep efficiency of carbon-dioxide recovery is increased by generating a foam in situ to block the highly permeable features of the underground formation. U.S. Pat. No. 3,342,256, issued to Bernard et al., discloses alternative methods for generating foam in situ to prevent channeling of carbon dioxide into high permeability channels away from the zone to be treated. In one embodiment, a small amount of a surfactant or foaming agent is dissolved in the carbon dioxide, which is maintained as a dense fluid or liquid at pressures in excess of about 700 psig to ensure solubility. A subsequently injected drive medium, such as water, forces the carbon dioxide-surfactant mixture through the formation to a production well where production continues until the produced fluids exhibit an undesirably high water/oil ratio. Production is then terminated, and the formation is depressurized to allow dissolved gases to come out of solution and form the foam. As the foam expands, it drives additional oil towards the producing well.
Relying upon gases released in low pressure zones to generate the foam, however, presents certain disadvantages. When the foaming agent is dissolved directly into carbon dioxide or into carbonated water, a large portion of the gaseous carbon dioxide released in the low pressure zone does not go to generating foam, but is preferentially absorbed into the crude. And if the released carbon dioxide migrates into a high pressure region, solubility of carbon dioxide is increased and may approach miscibility at pressures in excess of about 700 psig. These difficulties are not encountered if the foaming agent is dissolved in a hydrocarbon vehicle, but the cost of liquid hydrocarbons is generally prohibitive. Moreover, a hydrocarbon-soluble surface-active agent generally emulsifies the oil and restricts its movement through the reservoir. The upshot is that increasing the areal sweep efficiency of the recovery method by generating foam in situ is much more difficult and expensive in the reservoir than laboratory results might otherwise indicate.
A method of gas injection is disclosed by Holm in U.S. Pat. No. 4,706,752 (which is hereby incorporated by reference). This method discloses the use of a water-soluble surface active agent, and then a gas mixture of carbon dioxide and a noncondensable, nonhydrocarbon gas which is insoluble in viscous crude. A foam forms in-situ which is used for blocking the escape of solvent fluids into higher permeability zones of the reservoir during enhanced recovery. Holm's method is not concerned with the actual process of emplacing the foam. Holm does not saturate the formation with a calculated volume of surfactant, to ensure that foam can be generated and to produce more stable foam. Holm merely modifies the "foam drive process" of displacing oil, and does not even recognize the need to emplace the foam at a selected location in the reservoir. Holm is instead primarily concerned with modifying the vertical injection profile of the injector well.
T. M. Jonas et al. (including Applicant) published SPE Paper No. 20468, entitled "Evaluation of a CO.sub.2 Foam Field Trial: Rangely Weber Sand Unit" on Sep. 23, 1990. Jonas et al. recognized a problem caused by the existence of thief zones, which are high permeability zones in the selected formation where an injected fluid could escape, rather than be properly emplaced in the desired portion of the formation. The method utilized by Jonas et al. comprised injecting a surfactant slug, followed by injecting a foam, which was followed by injecting a CO.sub.2 chase gas.
Jonas et al. never realized the importance of presaturating the reservoir with a surfactant. The authors maintained that the advantage of emplacing foam by displacing a slug of surfactant is in the simplicity of operation and the lowest injection cost of three possible methods. Also, Jonas et al. discussed the disadvantages of injecting a surfactant first, which include low foam resistance and foam stability factors, the lack of control over the process once all the surfactant is injected, and the danger that the gas and liquid may exit from different intervals in the formation.
Jonas et al. did not discuss any calculation of a preferred amount of surfactant to inject, prior to the injection of foam, or even the need to inject a preferred amount of surfactant. There is no discussion of any advantage gained in foam quality by presaturating part of the formation with a surfactant.
The prior work is limited in the attempts at foam emplacement, in that no suitable method has been designed which saturates a productive reservoir with a surfactant, followed by injections of gas and surfactant, in order to plug thief zones in the formation and to generate a foam of enhanced quality. There is therefore a need for such a method for use in producing oil from a reservoir, utilizing the injection of surfactants and gases.